Good day, everybody, and welcome to Kosmos Energy's Second Quarter 2025 Conference Call. As a reminder, this call today is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Kosmos Energy.

Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our second quarter 2025 earnings release. This release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today to go through the materials are Andrew Inglis, Chairman and CEO; and Neal Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report stock exchange announcement and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'll start off the call by talking about Kosmos' priorities, reinforcing the key messages I gave last quarter before updating you on progress across the portfolio. Neal will then walk through the financials and the work we've been doing to enhance the resilience of the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on Slide 3. As we navigate the ongoing commodity price volatility, our key priorities have not changed. Last quarter, I talked about growing production and reducing costs to prioritize free cash flow, while continuing to strengthen our balance sheet. I'm pleased to say we've made good progress this quarter across each of these areas. Starting with production. In June, we announced the Gimi floating LNG vessel had achieved Commercial Operations Date or COD, a key milestone for the GTA project. COD is achieved when LNG production is tested for a period of 72 hours at the annual contracted rate of around 2.45 million tonnes per annum equivalent. The FLNG has a nameplate capacity of around 2.7 million tonnes per annum and we're targeting reaching that level in the fourth quarter of the year. The project has now lifted 6.5 gross cargoes year-to-date. In Ghana, we're pleased that drilling and Jubilee has restarted with the first producer well of the '25/'26 drilling program now online. Initial gross production from the well is around 10,000 barrels of oil per day, in line with our expectations. We have also optimized the drilling program by accelerating the scheduled rig maintenance in 3Q, which allows us to drill a second producer this year, replacing a previously planned injector. This planned producer well is expected to add further Jubilee production around the end of the year ahead of four or more wells planned in 2026. I'll talk about that alongside 2Q Jubilee production later in the material. In the Gulf of America, the partnership has drilled the Winterfell-4 well with completion operations underway, that went as expected online around the end of the quarter. We are now approaching Kosmos' record high production levels with further near-term growth expected as we push GTA towards the FLNG nameplate capacity and bring on more wells at Jubilee and Winterfell. Moving to costs. We focused on three areas and are making good progress across all three. Firstly, on CapEx. CapEx in the first half of 2025 was around $170 million down around 65% from the first half of 2024 as we come out of a heavy investment period and start to see the benefits of those investments. With a sharp focus on CapEx in 2025, we've reduced our full year CapEx forecast from around $400 million to around $350 million with the first half actual supporting its lower forecast as we slow down some longer-term investments. Secondly, on OpEx. The largest opportunity for OpEx reduction is on GTA, and we're seeing OpEx per BOE fall as production ramps up. We're also targeting the refinancing of the GTA FPSO in the second half of the year, and we're working with the operator to explore alternative lower-cost operating models, which could further drive down costs across the project. And thirdly, overhead. We remain on track to deliver $25 million of targeted savings by the end of this year, with the full benefit being seen in 2026 and beyond. And finally, the balance sheet, where we continue to prioritize our financial resilience with a focus on cash flow and debt paydown. On liquidity, we're taking steps to address our upcoming debt maturities, as part of today's material, we announced we've agreed indicative terms for a term loan of up to $250 million secured against our Gulf of America assets and we'll anticipate using the proceeds to repay our 2026 bond maturity. We're also progressing additional financing activities to fund some of our longer-dated maturities. On hedging, we took advantage of higher prices in late 2Q and early 3Q to hedge more 2026 oil production with 7 million barrels now hedged in 2026. We're looking to hedge around 50% of 2026 production by the end of this year. And finally, on the RBL to reflect the timing impact of GTA ramp-up costs on leverage, we were granted a waiver from our banks on the debt cover ratio covenant through to March 2026. Neal will talk about all of these in more detail later. But in summary, we're making good progress against our financial objectives. Turning to Slide 4, which looks at operations for the quarter. Starting with the GTA project in Senegal and Mauritania. Second quarter net production was just over 7,000 barrels of oil equivalent per day, and the partnership lifted 3.5 gross LNG cargoes, as previously communicated. As mentioned on the previous slide, the FLNG commercial operations date was achieved in late June. This is an important operational and financial milestone for Kosmos as it signals the end of us funding the NOC's CapEx on the project. In Ghana, total net production was around 29,100 barrels of oil equivalent per day. Jubilee gross production of around 55,000 barrels of oil per day was lower than expected in the second quarter, driven by 9 days of planned FPSO shutdown, a period of riser instability following the restart, which has since been addressed and the performance of some wells in the eastern side of the field. I'll talk more on the following slides about how the partnership is addressing these issues and the actions being taken to reestablish the full production potential of the field. As mentioned on the previous slide, the first producer well of the '25/'26 program was brought online late last month and is performing well. Jubilee gross gas production was around 16,600 barrels of oil equivalent per day in the second quarter. In early June, we announced that we signed an MOU with the government of Ghana to extend the licenses to 2040. The license extensions are a win-win for the project partners and the government, with partners now planning long-term investments in the field to maximize value for all stakeholders. We are working with our partners and the government to finalize the documentation targeting completion in the second half of the year. When I met with President Mahama earlier this year, we discussed his desire to reinvigorate the oil and gas sector in Ghana with increased investment in some of the country's most valuable assets. The license extensions on Jubilee and TEN are aligned with that agenda. At TEN, gross oil production in the quarter was just under 16,000 barrels of oil per day. In the Gulf of America, net production was around 19,600 barrels of oil equivalent per day at the upper end of guidance, driven by strong performance from the Kodiak and Odd Job fields. At Winterfell, the partnership has drilled the #4 well with the completion operations underway and the well is expected online later this quarter. On Tiberius, we continue to advance the development with our 50-50 partner, Oxy with FID targeted next year. In Equatorial Guinea, net production was just under 8,000 barrels of oil per day, lower than expectations due to some subsea pump mechanical failures at Ceiba. The operator expects the first replacement pump to be installed in the fourth quarter, with production expected to rise thereafter. Turning to Slide 5. At GTA, we continue to see a lot of positive progress with the project now fully operational. Year-to-date, we've lifted 6.5 gross cargoes, and the cadence of cargo listings is increasing as production ramps up. Further progress is expected with production rising towards nameplate capacity of 2.7 million tonnes per annum in the fourth quarter. Production of the project is expected to fluctuate slightly with seasonal temperatures with higher production expected during the winter months when the air and sea temperatures occur. Full year guidance of 20 gross cargoes reflects a slightly slower production ramp-up that we saw in the same quarter and early third quarter. Importantly, the subsurface is performing well, which is a key factor as we plan future expansion phases. As a reminder, there is around 25 Tcf of discovered gas in place at GTA. Phase 1 only requires around 3 Tcf for 20 years of production at the contracted rate. This is a world-class gas resource with significant running room. The partnership also expects the first condensate cargo late in the third quarter, a meaningful additional revenue stream for the project. On operating costs, both start-up and commissioning costs should start to fall away in the second half of the year. We're also progressing the refinancing of the FPSO lease targeting completion in the second half of the year. Additionally, the partners are working with the operator to explore alternative lower-cost operating models to drive down costs further. As we look out with Phase 1 now fully operational, the next major opportunity to enhance value is through future expansion. Phase 1 plus, a low-cost brownfield expansion that leverages the existing Phase 1 infrastructure to enable gas production to double at a fraction of the cost through increased LNG production and domestic gas to our host countries. During an official visit to the U.S. in July, the Presidents of Senegal and Mauritania met with President Trump at the White House. President Faye of Senegal spoke positively to President Trump about Kosmos and our critical role in discovering the GTA field 10 years ago. He also talked about the importance to Senegal of U.S. investment from companies like Kosmos and the joint opportunities that could be created through investment in sectors core to the country's economic growth, such as natural gas. The videos of the meetings are online and worth watching. Turning to Slide 6, 2025 is an important year for our operations in Ghana as we return to drilling. The timeline on the slide shows the journey we are on to deliver the full potential of the Jubilee field. The first half of 2024 marked the end of the previous 3-year drilling campaign, which was done using 4D seismic shot in 2017. At the end of that drilling campaign, Jubilee production peaked above 100,000 barrels of oil per day. In the second half of the year, we saw the start of a 12-month drilling hiatus, resulting in some expected natural decline of the field, which was exacerbated by facility issues that we talked about in detail last year, namely reliability, water injection, and power generation. The first half of 2025, the partnership carried out a significant facilities work scope on the FPSO during the scheduled shutdown. While voidage replacement for the first half of the year has been above 100%, production declines have been higher than anticipated in certain wells in the eastern side of the field, including Jubilee Southeast. Riser-based gas lift was introduced to the eastern side of the field, which has helped to restore and stabilize production and plans are in place to do the same on the western side of the field in the future. In early 2025, we acquired new 4D across the field, the first since 2017 to ensure the next set of wells we drill in Jubilee are the best targets derisked with the best data and technology. A key event in the second quarter was the arrival of the rig to commence the '25/'26 drilling campaign. In July, we brought the first new well online in over a year, a producer in the Jubilee main reservoir with initial gross production of around 10,000 barrels of oil a day. The 2025 rig program has been optimized to drill a second producer well in the Jubilee Main field following a period of scheduled rig maintenance. The second producer well is expected online around the end of the year. We're excited to see the enhanced imaging of the fast-track 4D seismic data now coming through, which we plan to further improve using ocean bottom node seismic or OBN, which we expect to acquire later in the year. I'll talk more about that on the following slide. As we look forward to next year and beyond, we're back to a more regular drilling cadence with four wells committed in 2026, which will start to benefit from the new seismic. Turning to Slide 7. I want to spend some time on this slide talking about the importance of consistent drilling and how the partnership is planning to use the latest technologies to deliver the full potential of Jubilee. Using cutting-edge seismic technology to enhance resource recovery in mid-life fields is a growing theme across the industry with recent communications from some of the majors highlighting the significant role they expected to play over the coming years. The 4D narrow-azimuth seismic or NAZ shot in the first quarter of the year was the first seismic acquired over the field since 2017. This new seismic data, processed with the latest technology, is generating a better understanding of the subsurface through enhanced imaging, which is helping to identify new undrilled lobes and unswept oil. As can be seen on the slide, the modern NAZ data on the bottom right shows much greater definition of existing reservoirs and yields an improved understanding of fluid movements over time compared to the legacy seismic in the top right. The improved imaging of the new data also provides greater visibility and understanding of deeper potential. At Kosmos, we've taken the lead in coupling this modern seismic with new AI-enhanced data interpretation and reservoir modeling to maximize recovery. As mentioned on the previous slide, we're planning to acquire OBN data over the field later in the year, which will enhance the velocity model to further uplift the NAZ processing. The velocity model inserts to the two images on the slide show the evolution and improvement in clarity from 2017 to the present day, and we think there's more to go with OBN data. The second message on the slide I want to focus on is drilling. We've talked at length in the past about the need for regular drilling on Jubilee, a key part of delivering the field's potential alongside high facility uptime and sustained water injection. As I mentioned, the '25/'26 drilling program is now underway with the first Jubilee producer, J-72, online and the second Jubilee main field producer expected online around the end of the year. Following the completion of that well, the rig is scheduled to drill four wells in Jubilee in 2026, targeting well-defined main field producers supported by good adjacent well control, similar to J-72. Going forward, we expect three to four wells per year will be needed to maximize the field's full potential over a multiyear period and sustain higher production levels. With the license extension MOU, the partnership can now plan for long-term investment in Jubilee, which should also drive a material uplift in 2P reserves. In summary, Jubilee is a big field that we expect will get bigger through regular drilling supported by new imaging and reservoir management technology. Turning to Slide 8. The Gulf of America second quarter performance was good with production at the upper end of guidance helped by strong output from both Odd Job and Kodiak. At Winterfell, the #4 well was drilled in the second quarter and is anticipated to come online late 3Q. The well is expected to contribute a net rate to Kosmos of around 1,000 barrels of oil equivalent per day. On our development activity, we, together with Oxy, continue to progress Tiberius, an outboard Wilcox discovery, working on improved lower-cost development plans supported by new OBN seismic that we expect to acquire later in the year. FID would then be targeted for next year. Gettysburg is a discovered resource opportunity we acquired in a previous lease sale in the Norphlet trend. To advance the project, we brought in Shell as a 75% partner and operator and are working alongside them in a joint team to progress a low-cost single well development that will be tied back to Shell's operated Appomattox platform. That concludes the review of the portfolio, and Neal will now take you through the financials.

Thanks, Andy. Turning now to Slide 9, which looks at the quarter in detail. Production was higher sequentially due to GTA coming on and strong performance in the Gulf of America, partly offset by lower production in Jubilee and Equatorial Guinea. Production did come in lower than guidance, mainly due to the ramp-up timing on GTA, which we communicated in June, and lower Jubilee production in the quarter. With GTA ramped up and the first Jubilee well online in July, current production is approaching record highs, as Andy previously mentioned. With additional wells at Jubilee and Winterfell, the installation of replacement pumps at Ceiba, and ramp-up further of GTA targeting the FLNG nameplate capacity, we expect production to continue to rise quarter-over-quarter into 2026. OpEx per BOE, as shown on the slide, excluding GTA, was higher in the quarter, largely reflecting the 1/10 lifting we expect this year since TEN operating costs are booked in the quarter, the cargo is lifted. G&A was lower as we start to see the impact of some of the overhead savings coming through. And finally, CapEx came in under budget due to the timing of activity in the Gulf of America and lower GTA costs in the quarter. As Andy discussed earlier, we have lowered our full year CapEx guidance to approximately $350 million from $400 million with 1Q and 2Q CapEx demonstrating we are on track to achieve the lower amount, which we believe is sustainable into 2026. With our CapEx and NOC funding winding down and production increasing, at current oil prices, we are generating free cash flow. While the timing has been slightly delayed, we remain focused on maximizing cash flow in the near term and reducing the absolute amount of net debt. I also want to mention that while working capital is difficult to predict on a quarterly basis, we do expect a working capital draw in the third quarter to reflect the timing of some payments. Turning to Slide 10. As Andy said in his opening remarks, one of the priorities for the company this year is enhancing the resilience of the balance sheet, and we've made progress in several key areas recently. On liquidity, we have agreed indicative terms for a senior secured term loan with an investment-grade counterparty at a cost similar to our existing RBL for up to $250 million, which we would anticipate using to repay the outstanding 2026 unsecured notes. This facility would be secured against our assets in the Gulf of America with a final maturity date four years after closing, which is anticipated by the end of the third quarter. The chart on the right shows the pro forma impact of this transaction on our maturity schedule, assuming we fully draw down on the new facility to repay the outstanding 2026 notes. Through the second half of this year, we plan to continue working on accessing additional attractive sources of liquidity to potentially repay some of our other longer-dated maturities. On hedging, we continue to add additional protection against commodity price downside through the back half of the year into 2026. For the remainder of 2025, we have 5 million barrels of oil production hedged with a $62 per barrel floor and a $77 per barrel ceiling. We also took advantage of higher prices in late 2Q and early 3Q to add more hedges for 2026. We now have 7 million barrels of oil hedged next year with a floor of $66 per barrel and a ceiling of $75 per barrel. On CapEx, I talked on the previous slide about reducing full year guidance to approximately $350 million from $400 million. The chart on the bottom right shows a material drop in quarterly CapEx from last year with lower levels of CapEx expected to continue as we prioritize free cash flow. And finally, we worked with our banks to amend the debt cover ratio calculation for the RBL, increasing the ratio for the next two scheduled test dates to reflect the timing impact of start-up of the GTA project on the backward-looking leverage calculation. The debt cover ratio will return to the originally agreed level thereafter when full year revenues from the GTA project are better aligned with operating expenses. So in summary, we remain proactive on improving the balance sheet, raising liquidity, increasing hedging and reducing costs, and we'll continue to update the market as we make further progress in the second half of this year. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to Slide 11 to conclude today's presentation. As I said in my opening remarks, our near-term focus is on growing production, reducing costs, and enhancing the resilience of the balance sheet, and we're making good progress in all three areas. As we look beyond the near term, there's significant scope to add long-term value for our investors through high-quality production and development opportunities across the portfolio. On GTA, with the first phase now fully operational, we are focusing our efforts towards reducing costs and doubling production to further drive down unit costs through advancing the low-cost brownfield expansion that leverages the existing infrastructure. In Ghana, Jubilee is a big mid-life field with significant reserves yet to be produced, which can be accessed by consistent drilling enabled by new technology and the license extension. The Gulf of America, a proven basin with significant running room, continues to advance an attractive portfolio of infrastructure-led exploration and development options in the Outboard Wilcox and Norphlet trends that leverage Kosmos' capability. In Equatorial Guinea, our assets should deliver cash flow as we selectively invest in production optimization. So in summary, Kosmos has a diverse, differentiated portfolio with a 2P reserves to production life of over 20 years with considerable discovered resource beyond that. The conversion of this discovered resource into high-value reserves and then into production will be done at the right pace in a capital-efficient manner, prioritizing cash flow and the balance sheet in the near term. We look forward to delivering on these near-term objectives, which will support long-term value creation for our investors. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

Our first question is from Charles Meade with Johnson Rice.

Andy, I want to ask a question about Jubilee. You've given us a lot of great detail here, and I love all the technical detail. But looking at the story from the top down, you mentioned that in the first half of '24, the field was producing over 100,000 barrels. A year later, you're down to 55,000 or let's call it, 60,000 adjusted for downtime. So that 40% decline in the year strikes me as high, maybe anomalously high. But if I look at it from a different way and say, okay, well, you need to drill four new producers every year to keep the field flat. And if those producers come in like your latest one, maybe that 40% annual decline is the slope you're fighting every year. So I wonder if you could comment on whether that's a valid way of looking at it and what you'd add to that picture.

Yes. Thanks, Charles. Look, it's a really good question. I think when you look at it from the top down, I think you rightly focused on where we are in 2Q. Not only was the shutdown a little challenged, but we did have the additional issues of the riser instability, which we've ironed out. So you sort of have to look at 2Q in the right context, yes. But it was also impacted, I think, by higher-than-expected decline, certainly in some of the wells on the eastern side of the field, in particular, Jubilee Southeast. So you go, okay, what are we actually doing about that now? I think we talked in quite a lot of detail in the prepared section about the impact of two things. One is better data. We're really pleased with the uplift we're seeing from the fast track data in the NAZ, and again, you need to remember this is fast track, very early product. And to me, the uplift is huge in terms of our ability to see better opportunities in the field, both from undrilled lobes and unswept oil. So you're starting to see now a much clearer picture. And I think we did suffer towards the end of the last drilling campaign from the quality of the data we stated back to 2017. So you've got much better data, and then the ability then to improve it further than NAZ to the OBN, I think we're going to see a big uplift in the velocity model. So I think the imaging is only going to become clearer. And then as you rightly say, the second part of the story is how do we harness the improved data? You've got to drill regularly. And when we've said all along that you need to get three to four wells in a year to maintain the production levels. So if you sort of take that and track forward, I think we drilled the first of those wells and brought it online last month. We're seeing production rising as a result. We hope to get a second well on around year-end. I think that can push production up to around 70,000 barrels a day. So the drilling is more than offsetting the underlying decline and leading to growth. And then four more wells in '26, we think they're likely going to be producers. If you think each of those is adding 5,000 to 10,000 barrels a day, you can see your way even with the decline that we're seeing, building up towards that sort of 90,000 barrels a day. So I think that's how you get back to where we need to be. And then you can sort of rinse repeat because you've got quality data, and you're starting to deliver a regular consistent drilling program targeting high-quality wells. So yes, 2Q was lower than expectation, and you sort of did the math on that. But I think even when you adjust it for the one-offs that were in there and then you start to look at the performance we're seeing from some of the wells that we're drilling, you can reestablish the potential of the field. But it's going to require the two things we talked about: good data, and I think I'm really pleased with what we're seeing with the NAZ. I think the fast track NAZ will only get better with the four products and then the uplift from the OBN and then back to a regular drilling program.

Got it. That's great detail, Andy. Regarding GTA, you mentioned in your prepared comments, in the slides, and also in the press release about exploring different operating models to lower costs. Can you provide insight into what those models might be or, more importantly, what the potential cost reduction could be? I'm assuming you mean in absolute terms, not as a precursor to producing it on a unit basis?

Yes, absolutely. It's important to remember that GTA has been a significant project for us. The start-up of a major facility like this, an LNG project, always presents challenges in the first year as we work towards stability and eliminate start-up and commissioning costs. Our top priority is to achieve steady production levels. We reached commercial operation in June and are currently maintaining those levels while producing at the annual capacity. However, we recognize that there is still room for improvement. We see opportunities in optimizing individual trains, which can help us reach and exceed nameplate capacity as we progress through the second half of the year. Additionally, we plan to reduce start-up and commissioning costs to lower levels, which we expect to accomplish in the fourth quarter. Looking ahead, discussions with the operator will focus on refinancing the FPSO in the latter half of the year, which will greatly benefit both Kosmos and the national oil companies. We will also explore ways to further decrease operating costs. Ultimately, our goal is to assess various operating models. Currently, the model relies solely on BP personnel for both the FPSO and the hub, but we will consider other approaches used elsewhere that could enhance our competitive position. There is significant potential for cost reduction, which involves addressing our cost structure from all perspectives, not just by increasing volume.

Our next question is from Matt Smith with Bank of America.

Thanks for all those details so far. Perhaps I just have one sort of broad question on CapEx. Welcome to see that coming down in the guidance for 2025. I guess my question really is, is that CapEx envelope now well below $400 million at around $350 million? Is that a sensible CapEx envelope to think about going forward? You referenced, of course, Tiberius FID potentially next year at some stage, Phase 1 plus on GTA. So I'm just wondering, are you comfortable that you could operate within that $350 million going forward? Or should we expect you to perhaps need to go above that if you were to progress those projects? And perhaps if I tack on a second one, related to that is just whether you're seeing any momentum on that GTA Phase 1 plus project at the moment, good alignment from the partnership or how close to near term is progress there, I guess, is the crux of my question, please.

As we consider the reduction in capital expenditures from $400 million to $350 million, our focus is on maximizing the value of every dollar spent while prioritizing free cash flow. There are numerous opportunities across our portfolio, but we have primarily slowed down some of the longer-term projects, particularly Tiberius. Looking ahead to 2026, while we haven't provided specific capital expenditure guidance yet, the main need for capital will be for the four committed wells in Jubilee. In Equatorial Guinea, there are no significant capital demands. With regards to GTA, Phase 1 is not expected to significantly impact our 2026 expenditures, and the final investment decision for Tiberius will likely come towards the end of that year. Therefore, I believe that maintaining a capital expenditure of around $350 million can support the company's growth, especially with the contributions from the Jubilee wells, without hindering our future growth trajectory. In summary, a capital expenditure of approximately $350 million seems appropriate for continued growth. Beyond that, in the 2027 and 2028 timeframe, we expect some investment in Tiberius and an expansion of Phase 1. On Phase 1, the key factor is the subsurface performance. Currently, we have three wells online, all performing as expected. This success was crucial for gaining partnership alignment regarding reservoir performance. We started production at the end of last year, and we have over seven months of data, which is encouraging. The reserves exist to allow for project expansion, and there is consensus within the partnership regarding a brownfield expansion that could double the current production rates, with only a minimal additional investment required. Additionally, there is a commitment to directing incremental gas towards LNG and domestic supply, reflecting governmental demand for domestic gas. We are addressing how rapidly that call for domestic gas can increase, along with the need to enhance the Gimi's capacity for additional LNG. Currently, we are examining how to allocate the incremental 300 to 400 million standard cubic feet. Therefore, a key issue remains the number of wells necessary to support the additional volume we anticipate. We are gaining a clearer understanding of reservoir performance, which will help us refine our well count. The ongoing work focuses on determining how many wells are needed, their timing for supporting the additional volume, and the potential uplift from Gimi to achieve those goals.

Our next question is from Bob Brackett with Bernstein Research.

I have a clarification maybe and then a question. The clarification follows what Charles had alluded to a 40% decline in the 100,000 a day Jubilee field. The way I read the release is something more like three to four wells a year to maintain flat performance and maybe those split between producers and injectors, and that gets you to something like a 15% to 20% base decline. Is that the better way to think of it?

Yes, it is, Bob. Yes. I think you've described it accurately. So if you think about the near-term program, we're going to heavily weight producers because we believe we've got sufficient injection capacity as you ramp up from where we are today up to that sort of 90,000 barrels of oil per day. So you don't really need today additional injectors. So you can sort of high-grade the program to producers, but to be able to do that, you need the data, etc., as I talked through with Charles. When you're at that higher level, then I think the decline rate that you've talked about is the level in which you can manage the field. Therefore, you will need injectors because you've got a high level of offtake. Therefore, a mix of producers and injectors; three to four wells per year is the right way to think about it.

And then I guess my core question is somewhat related, which is on the license extension. You have an MOU. Can you share whether there's any change in the fiscal terms or any work program commitment? Or is that still up in the air?

No. What we've said, Bob, is that we've described the intent of the MOU and the dimensions that it covers. It's a win-win really for both the government and ourselves. What we're doing is there is a decrease in the gas price, but there's more volume. So we've committed to move the volume up to 130 million standard cubic feet a day with a small discount to the gas price. There is an undertaking to drill up to 20 wells. And clearly, the number will depend on the emerging opportunity set that we see from the NAZ. But today, we see it as being a positive view that we're getting of the reservoir. No change to the fiscal terms. It's under the existing law. Those are the key elements. So I think for us, the most important part is that you can properly invest in the field to deliver a consistent drilling program where you're continuing to invest in the data because I think we can see the uplift from the NAZ having sort of not been shooting seismic for almost eight years. We need to get back to a regular program probably every three years where you shoot a NAZ, probably no need to redo OBN, but we would come back to that given that you calibrated the velocity model. That's the real win-win from this: that with a greater purview, you can invest properly upfront to deliver that regular program that we talked about, where the data is enabling you to drill the best wells that are available.

Our next question is from Alexa Petrick with Goldman Sachs.

I wanted to ask one question on GTA costs. I think the 3Q guide came in a little higher than our expectations. So just want to get your sense of what's in those costs. How do we think about 4Q? And then any sense of how we should think about it on a per BOE basis for 2026?

Yes. Neal, do you want to pick that up?

The three components in the GTA cost numbers are the FLNG toll, the FPSO lease, and regular field operational expenses. The FLNG toll was slightly higher in the second quarter due to some bonus payments to Golar, but this is expected to normalize to just over $2 per Mcf on a recurring basis, stabilizing as we move into the latter half of this year and into next year. The operating cost of the FPSO lease is approximately $15 million per quarter, and we are currently working on refinancing that, which is on track. Once complete, we should see the cost reductions reflected. The third component, field operational expenses, should remain steady from the second to the third quarter as we continue to adjust for start-up and commissioning costs, with a decrease expected in the fourth quarter. We anticipate maintaining these costs into 2025 and 2026 while also exploring alternative models. On a per unit basis, we expect to see improvements on both sides, with increasing volume and decreasing costs.

Okay. That's helpful. And then I just wanted to ask, we recognize right now we're in a period of GTA start-up costs, production is ramping. But as we think about getting to a point where we have more normalized volumes and costs come off, any thoughts about how we should think about a normalized free cash flow for the business?

Yes. Our perspective on this hasn’t really changed. We aim to reduce the breakeven point for the business to around $50 to $55 per barrel. The sensitivity to oil prices means that for every $5 increase in selling price, we expect about $100 million in additional free cash flow. While this may not align perfectly on a quarterly basis due to the timing of liftings, we are targeting this rate consistently across the business.

Our next question is from Mark Wilson with Jefferies.

A couple of questions, please. First, on GTA, thinking ahead to Phase 1 plus, is the most important thing we should be looking for a gas sales agreement either with Senegal, Mauritania, or with a third party? That's the first question. And then on Jubilee, a lot of commentary and detail in the presentation and some hindsight views, I would say, as well. The question I have going forward is particularly with this new seismic data and the processing of that and the work that needs to be done on the longer term, should you be the operator of that field? And is that something we're looking for?

Thank you, Mark. Yes, regarding the first question, I was clear earlier that we aim to collaborate with the partnership, which includes the government, to determine the right balance between domestic gas and increased LNG sales. This optimization process involves understanding the gas levels they can manage, the expected ramp-up, and what a gas sales contract would entail. As we approach the final investment decision, we need clarity on the gas sales expectations. The government understands the demand, and it’s evident that the growing economy requires leveraging gas to replace more expensive heavy fuel oil. This transition presents a genuine economic benefit for everyone involved, so I don't see it as an obstacle, but it must be addressed. Regarding your second question, we have a strong working relationship with Tullow. It’s a productive partnership where we both bring unique skills to the table. Being based in the Gulf of America allows us to utilize seismic data and advanced acquisition techniques effectively. Currently, we are collaborating well with Tullow to combine our capabilities in this area to drive results. We are aligned on our operations, with the rig secured and six wells planned. What's critical is that we’re united in our approach, and both Kosmos and Tullow are adding value to this partnership.

Our next question is from Stella Cridge with Barclays.

Many thanks for all of the updates. I was wondering if I could ask on the debt side. So you mentioned that you're progressing additional financing options. I just wondered if you could talk about the different options that might be available to you, how far out on the curve that you're thinking about in terms of maturities, that would be great. And in the RBL, of course, you do have some requirements to address debt a reasonable amount ahead of time. I just wonder if you could talk about how confident you are in meeting some of those requirements of the lending, that would be good.

Yes, I'll take that. Regarding the further out maturities, our goal when we established the maturity schedule in the past was to leave some maturities available and then pay them off using the cash flow generated by the business. Our aim is not just to lower leverage but also to decrease the total amount of debt, which is why paying off the bonds with generated cash flow is sensible. This remains part of our plan, and a significant factor in this is oil prices. Given the fluctuations in oil prices, we decided it was wise to pay off the 2026 maturity early through refinancing. This offers us some flexibility along with other proactive financial measures we've taken to ensure a clear path forward. During this time, we will continue to work towards maximizing cash flow for the business to further reduce debt. Additionally, we will explore other attractive sources of capital to see if we can gain a cost advantage for addressing the 2027 and 2028 maturities, as they are currently trading at a discount. If we can obtain low-cost financing secured by our assets, it represents an opportunity for a positive return. Our plan is to complete the Gulf facility this quarter and then assess those options further. This will depend on market conditions: if they continue to trade at a discount, we could expedite net debt reduction through the early retirement of those bonds. It's a continuous evaluation process. As for your second question regarding the RBL, we comfortably passed the test in March. We utilized an RBL price deck to demonstrate that, considering existing liquidity and expected cash generation until our maturities, we have adequate resources to meet our obligations. Despite the fluctuations in oil prices, we are still well above the borrowing base price decks and are optimistic about future cash generation. Especially with the Gulf facility in place, I expect we will maintain good coverage as we regularly pass through those tests.

Our next question is a follow-up from Bob Brackett with Bernstein Research.

This has to do with GTA. And you mentioned a domestic gas component. Can you remind me, is that a pipe to St. Louis? Or is that some LNG into regas and, say, the car or something? What's envisioned there?

No. I think the primary source would be pipeline gas, yes. This would be a pipe gas solution rather than LNG, although there is an LNG regas facility. You could add incremental volume that way. But I think what we're looking at today, Bob, is a more permanent solution.

Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone for joining today. You may disconnect your lines at this time and thank you for your participation.